Method and apparatus for injecting steam into a geological formation

ABSTRACT

The present invention generally provides a method and apparatus for injecting a compressible fluid at a controlled flow rate into a geological formation at multiple zones of interest. In one aspect, the invention provides a tubing string with a pocket and a nozzle at each isolated zone. The nozzle permits a predetermined, controlled flow rate to be maintained at higher annulus to tubing pressure ratios. The nozzle includes a diffuser portion to recover lost steam pressure associated with critical flow as the steam exits the nozzle and enters a formation via perforations in wellbore casing. In another aspect, the present invention assures that the fluid is supplied uniformly to a long horizontal wellbore by providing controlled injection at multiple locations that are distributed throughout the length of the wellbore. In another aspect, the invention ensures that saturated steam is injected into a formation in a predetermined proportion of water and vapor by providing a plurality of apertures between a tubing wall and a pocket. The apertures provide distribution of steam that maintains a relative mixture of water and vapor. In another aspect of the invention, a single source of steam is provided to multiple, separate wellbores using the nozzle of the invention to provide a controlled flow of steam to each wellbore.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a continuation-in-part of co-pending U.S. patentapplication Ser. No. 10/097,448, filed Mar. 13, 2002, which is hereinincorporated by reference.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention relates to the production of hydrocarbon wells.More particularly the invention relates to the use of pressurized steamto encourage production of hydrocarbons from a wellbore. Moreparticularly still, the invention relates to methods and apparatus toinject steam into a wellbore at a controlled flow rate in order to urgehydrocarbons to another wellbore.

2. Description of the Related Art

To complete a well for hydrocarbon production, a wellbore drilled in theearth is typically lined with casing which is inserted into the well andthen cemented in place. As the well is drilled to a greater depth,smaller diameter strings of casing are lowered into the wellbore andattached to the bottom of the previous casing string. Casing strings ofan ever-decreasing diameter are placed into a wellbore in a sequentialorder, with each subsequent string necessarily being smaller than theone before it.

Increasingly, lateral wellbores are created in wells to more completelyor effectively access hydrocarbon-bearing formations. Lateral wellboresmay be formed off of a vertical wellbore, typically from the lower endof the vertical wellbore, and may be directed outwards through the useof some means of directional drilling, such as a diverter. The end ofthe lateral wellbore which is closest to the vertical wellbore is theheel, while the opposite end of the lateral wellbore is the toe.Alternatively, lateral wellbores may be formed in a formation merely bydirectional drilling rather than formed off of a vertical wellbore.After a lateral wellbore is formed, it may be lined with casing or mayremain unlined.

Artificial lifting techniques are well known in the production of oiland gas. The hydrocarbon formations accessed by most wellbores do nothave adequate natural pressure to cause the hydrocarbons to rise to thesurface on their own. Rather, some type of intervention is used toencourage production. In some instances, pumps are used either in thewellbore or at the surface of the well to bring fluids to the surface.In other instances, gas is injected into the wellbore to lighten theweight of fluids and facilitate their movement towards the surface.

In still other instances, a compressible fluid like pressurized steam isinjected into an adjacent wellbore to urge the hydrocarbons towards aproducing wellbore. This is especially prevalent in a producing fieldwith formations having heavy oil. The steam, through heat and pressure,reduces the viscosity of the oil and urges or “sweeps” it towardsanother wellbore. In a simple arrangement, an injection well includes acased wellbore with perforations at an area of the wellbore adjacent aformation or production zone of interest. The production zones aretypically separated and isolated from one another by layers ofimpermeable material. The area of the wellbore above and below theperforations is isolated with packers and steam is injected into thewellbore either by using the casing itself as a conduit or through theuse of a separate string of tubulars coaxially disposed in the casing.The steam is generated at the surface of the well and may be used toprovide steam to several injection wells at once. If needed, a simplevalve monitors the flow of steam into the wellbore. While the forgoingexample is adequate for injecting steam into a single zone, in verticalwellbores, there are more typically multiple zones of interest adjacenta wellbore and sometimes it is desirable to inject steam into multiplezones at different depths of the same wellbore. Because each wellboreincludes production zones with varying natural pressures andpermeabilities, the requirement for the injected steam can vary betweenzones, creating a problem when the steam is provided from a singlesource.

One approach to injecting steam into multiple zones is simply to provideperforations at each zone and then inject the steam into the casing.While this technique theoretically exposes each zone to steam, it haspractical limitations since most of the steam enters the highest zone inthe wellbore (the zone having the least natural pressure or the highestpermeability). In another approach, separate conduits are used betweenthe injection source and each zone. This type of arrangement is shown inFIG. 1. FIG. 1 illustrates a vertical wellbore 100 having casing 105located therein with perforations 110 in the casing adjacent each ofthree separate zones of interest 115, 120, 125. As is typical with awellbore, a borehole is first formed in the earth and subsequently linedwith casing. An annular area formed between the casing and the boreholeis filled with cement (not shown) which is injected at a lower end ofthe wellbore. Some amount of cement typically remains at the bottom ofthe wellbore. The upper and intermediate zones are isolated with packers130 and a lower end of one tubular string 135, 140, 145 terminateswithin each isolated zone. A steam generator 150 is located at thesurface of the well and a simple choke 155 regulates the flow of thesteam into each tubular. This method of individual tubulars successfullydelivers a quantity of steam to each zone but regulation of the steam toeach zone requires a separate choke. Additionally, the apparatus iscostly and time consuming to install due to the multiple, separatetubular strings 135, 140, 145.

More recently, a single tubular string has been utilized to carry steamin a single wellbore to multiple zones of interest. In this approach, anannular area between the tubular and the zone is isolated with packersand a nozzle located in the tubing string at each zone delivers steam tothat zone. The approach suffers the same problems as other prior artsolutions in that the amount of steam entering each zone is difficult tocontrol and some zones, because of their higher natural pressure orlower permeability, may not receive any steam at all. While theregulation of steam is possible when a critical flow of steam is passedthrough a single nozzle or restriction, these devices are inefficientand a critical flow is not possible if a ratio of pressure in theannulus to pressure in the tubular becomes greater than 0.56. In orderto ensure a critical flow of steam through these prior art devices, asource of steam at the surface of the well must be adequate to ensure anannulus/tubing pressure ratio of under 0.56.

Critical flow is defined as flow of a compressible fluid, such as steam,through a nozzle or other restriction such that the velocity at leastone location is equal to the sound speed of the fluid at local fluidconditions. Another way to say this is that the Mach number of the fluidis 1.0 at some location. When the condition occurs, the physics ofcompressible fluids requires that the condition will occur at the throat(smallest restriction) of the nozzle. Once sonic velocity is reached atthe throat of the nozzle, the velocity, and therefore the flow rate, ofthe gas through the nozzle cannot increase regardless of changes indownstream conditions. This yields a perfectly flat flow curve so longas critical flow is maintained.

Another disadvantage of the forgoing arrangements relates to ease ofchanging components and operating characteristics of the apparatus. Overtime, formation pressures and permeability associated with differentzones of a well change and the optimal amount (flow rate) and pressureof steam injected into these zones changes as well. Typically, adifferent choke or nozzle is required to change the characteristics(flow rate and steam quality) of the injected steam. Because the nozzlesare an integral part of a tubing string in the conventionalarrangements, changing them requires removal of the string, an expensiveand time-consuming operation.

Another problem with prior art injection methods involves thedistribution of steam components. Typically, steam generated at a wellsite for injection into hydrocarbon bearing formations is made up of acomponent of water and a component of vapor. In one example, saturatedsteam that is composed of 70 percent vapor and 30 percent water by massis distributed to several steam injection wells. Because the vapor andwater have different flow characteristics, it is common for the relativeproportions of water and vapor to change as the steam travels down atubular and through some type of nozzle. For example, it is possible toinadvertently inject mostly vapor into a higher formation whileinjecting mostly water into lower formations. Because the injectionprocess relies upon an optimum mixture of steam components, changes inthe relative proportions of water and vapor prior to entering theformations is a problem that affects the success of the injection job.

Additional problems are also encountered with injection methodsinvolving lateral wellbores. Although vertical wellbores typically havemultiple zones of interest which must be treated, lateral wellboresordinarily have only one zone of interest along the length of thelateral wellbore. Therefore, different pressures for different zones ofinterest, which are often desired for treating vertical wellbores, arenot necessary in treating the zone of interest in the lateral wellbore.For lateral wellbores, it is desirable for the entire zone of interestto be treated equally with compressible fluid at the same pressure alongthe length of the lateral wellbore.

Ordinarily, steam is injected from the heel of the lateral wellbore.Because the injection is from the heel of the wellbore, the steam oftenhas a higher pressure at the heel of the wellbore than at the toe due topressure loss in the steam resulting from frictional resistance alongthe length of the wellbore as the steam travels downstream. As a result,as steam travels along the horizontal wellbore, its pressure typicallyundesirably varies along the length of the wellbore.

Along the length of the lateral wellbore, the steam also tends toseparate, with the liquid phase flowing along the bottom of the wellboreand the vapor phase flowing into the upper portion of the wellbore.Because the phases tend to separate, the steam injected into the zone ofinterest along the wellbore may not be uniform in phase components. Itis desirable for the steam to have a uniform phase distribution (liquidto vapor ratio) along the length of the lateral wellbore so that thezone of interest is treated equally along its length.

There is a need therefore, for an apparatus and method of injectingsteam into multiple zones at a controlled flow rate and pressure in asingle wellbore that is more efficient and effective than prior artarrangements. There is a further need for an injection apparatus withcomponents that can be easily changed. There is a further need for aninjection system that is simpler to install and remove. There is yet afurther need to provide steam to multiple zones in a wellbore inpredetermined proportions of water and vapor. There is yet a furtherneed for a single source of steam provided to multiple, separatewellbores using a controlled flow rate. There is yet a further need foran apparatus and method for injecting steam into a zone of interestalong the length of a lateral wellbore at a controlled flow rate andpressure. There is yet a further need for an apparatus and method forinjecting steam into a zone of interest along the length of a lateralwellbore in predetermined proportions of water and vapor.

SUMMARY OF THE INVENTION

The present invention generally provides a method and apparatus forinjecting a compressible fluid at a controlled flow rate into ageological formation at multiple zones of interest. In one aspect, theinvention provides a tubing string with a pocket and a nozzle at eachisolated zone. The nozzle permits a predetermined, controlled flow rateto be maintained at higher annulus to tubing pressure ratios. The nozzleincludes a diffuser portion to recover lost steam pressure associatedwith critical flow as the steam exits the nozzle and enters a formationvia perforations in wellbore casing. In another aspect, the inventionensures steam is injected into a formation in a predetermined proportionof water and vapor by providing a plurality of apertures between atubing wall and a pocket. The apertures provide distribution of steamthat maintains a relative mixture of water and vapor. In another aspectof the invention, a single source of steam is provided to multiple,separate wellbores using the nozzle of the invention to provide acontrolled flow of steam to each wellbore.

The present invention further generally provides a method and apparatusfor injecting a compressible fluid at a controlled flow rate into ageological formation into a zone of interest along the length of alateral wellbore. In one aspect, the present invention provides a tubingstring with a pocket and nozzle within the lateral wellbore. The pocketis disposed concentrically around the tubing string. The nozzle permitsa predetermined, controlled flow rate to be maintained. An obstructingmember is placed opposite the nozzle to prevent the steam from flowingin the preferential direction of the nozzle to produce a substantiallyuniform distribution of steam pressure along the length of the wellbore.In another aspect, the invention provides a plurality of aperturescircumferentially distributed around the tubing string adjacent to thepocket to provide a distribution of steam that maintains a relativemixture of water and vapor along the length of the lateral wellbore. Inyet another aspect, multiple pockets with corresponding nozzles may bespaced along the length of the tubing string.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the manner in which the above recited features, advantages andobjects of the present invention are attained and can be understood indetail, a more particular description of the invention, brieflysummarized above, may be had by reference to the embodiments thereofwhich are illustrated in the appended drawings.

It is to be noted, however, that the appended drawings illustrate onlytypical embodiments of this invention and are therefore not to beconsidered limiting of its scope, for the invention may admit to otherequally effective embodiments.

FIG. 1 is a section view of a wellbore having three separate tubularstrings disposed therein, each string accessing a separate zone of thewellbore.

FIG. 2 is a section view of a vertical wellbore illustrating anapparatus of the present invention accessing three separate zones in thewellbore.

FIG. 3 is an enlarged view of the apparatus of FIG. 2 including atubular body with apertures in a wall thereof, a pocket formed adjacentthe body, and a nozzle having a diffuser portion.

FIG. 4 is an enlarged view of the nozzle of the apparatus showing athroat and the diffuser portion of the nozzle.

FIG. 5 is a graph illustrating pressure/flow relationships.

FIG. 6 is a section view of the apparatus illustrating the flow of vaporand water components of steam through the tubular member.

FIG. 7 is a section view of a lateral wellbore illustrating an apparatusof the present invention accessing a zone of interest in the wellbore.

FIG. 8 is an enlarged section view of the apparatus of FIG. 7 includinga tubular body with apertures in a wall thereof, a pocket formed aroundthe body, and a nozzle having a diffuser portion.

FIG. 9 is a side view of a sleeve with apertures for use with theapparatus of the present invention.

FIG. 10A-10D are section views showing the insertion of a removablenozzle portion of the invention.

FIG. 11 is a section view showing a removable sleeve with apertures.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT

The present invention provides an apparatus and methods to inject steaminto a geological formation from a wellbore.

FIG. 2 is a section view of a vertical wellbore 100 illustrating anapparatus 200 of the present invention disposed in a wellbore. A stringof tubulars 205 is coaxially disposed in the wellbore 100. In theembodiment of FIG. 2, the tubing string includes three enlarged area orpockets 210 formed therein, each of which define an annular area withthe casing and include a nozzle 215 at one end. The apparatus is locatedin a manner whereby the pockets formed in the tubular are adjacentperforated sections of the casing. Each perforated area corresponds to azone of the well to be injected with steam. Each pocket is preferablyformed in a sub that can be located in the tubular string and thenpositioned adjacent a zone. Each nozzle provides fluid communicationbetween the apparatus and a zone of interest. Each zone is isolated withpackers 130 to ensure that steam leaving the pocket via the nozzletravels through the adjacent perforations in the casing. Each nozzle isformed with a throat 250 and diffuser portion 245 (FIG. 4) toefficiently utilize the steam as will be described. In use, theapparatus 200 is intended to deliver a source of steam from the surfaceof the well to each zone and to ensure that each zone receives apredetermined amount of steam, and that amount of steam is determined bythe supply pressure at the surface and the characteristics of thenozzle. As shown in FIG. 2, the number of subs depends upon the numberof zones to be serviced. The subs are disposed in the tubing string withthreaded connectors 217 at each end. The packers 130 are typically cuppackers and each may include a pair of cup packers to prevent flowacross the packers in either direction.

FIG. 3 is an enlarged view of a portion of the tubing 205 and theadjacent pocket 210. Fluid communication between the tubular and thepocket is provided with a plurality of apertures 220 formed in a wall ofthe tubular adjacent the pocket. Additionally, a sleeve 225 is locatedin the interior of the tubular to permit selective use of the apertures220 depending upon the amount of steam needed at the zone. The sleeve225 is preferably fitted into the tubing at the surface of the wellprior to run in. The apertures 230 of the sleeve are constructed andarranged to align with the apertures 220 of the tubing 205. The use of asleeve having a predetermined number of apertures permits fewer than allof the apertures in the tubing to be utilized as a fluid path betweenthe tubing and the pocket. In this manner, the characteristics of thesteam at a particular pocket 210 can be determined by utilizing a sleevewith more or fewer apertures rather than fabricating a tubing for eachapplication. The sleeve 225 is sealed within the tubing with seal rings227 at each end of the sleeve 225. A slot and pin arrangement 344between the sleeve 225 and the tubing 205 rotationally aligns theaperture of the sleeve with those of the tubing. The flow of steam fromthe tubing through the apertures 230 of the sleeve is shown with arrows235. Steam in the pocket 210 thereafter travels from the nozzle throughthe perforations as shown by arrows 237. A portion of the steamcontinues downward as shown by arrow 238 to service another pocketlocated on the tubular string below.

FIG. 4 is an enlarged view of the nozzle 215 providing fluidcommunication between pocket 210 and an annular area 240 defined betweenthe tubing and the wellbore casing and sealed at either end with apacker (not shown). The nozzle 215 is threadingly engaged in the pocketand sealed therein with a seal ring 216. As stated, prior art nozzlesused in steam injection typically provide a critical flow of steam atlower annulus/tubing pressure ratios. At higher pressure ratios, theyprovide only a non-critical restriction to the flow of steam. Unlikeprior art nozzles, the nozzle of FIG. 4 includes a diffuser portion 245as well as a throat portion 250. In use, velocity of the steam increasesas the pressure of the steam decreases when the steam passes through anozzle inlet 251. Thereafter, the diffuser portion, because of thegeometry of its design, causes the steam to regain much of its lostpressure. The result is a critical flow rate at a higher annulus/tubingratio than was possible with prior art nozzles. While nozzles withdiffuser portions are known, they have not been successfully utilized toinject steam at a critical flow rate into a geological formationaccording to the present invention.

FIG. 5 illustrates a comparison of pressure and flow rate between aprior art nozzle (curve 305) and the nozzle of the present invention(curve 310). In a first portion of the graph, the curves 305, 310 areidentical as either nozzle will produce a critical flow of steam so longas the annulus/tubing pressure ratio is at or below about 0.56. However,if the annulus/tubing pressure ratio becomes greater than 0.56, theprior art nozzle is unable to provide a critical flow of steam andbecomes affected by annulus pressure and permeability characteristics ofthe formation. Because the nozzle of the present invention is so muchmore efficient in operation, it can continue to pass a critical flow ofsteam at higher annulus/tubing pressure ratios. In one embodiment, thenozzle can continue to pass a critical flow of steam even at anannulus/tubing pressure ratio of 0.9. The shape of curve 310 shows thatusing the nozzle of the present invention, critical flow is maintainedso long as the annular pressure does not exceed 0.9 of the tubingpressure.

FIG. 6 is a section view showing the interior portion of the tubing 205adjacent a pocket (not shown) and a single aperture 220 in the tubing205. For clarity, the sleeve 225 with its aligned apertures 230 is notshown. Illustrated in the Figure is a portion of water 265 and a portionof vapor 260 that includes water droplets. As stated herein, pressurizedsteam used in an injection operation is typically made of a component ofvapor and a component of water. The combination is pressurized andinjected into the wellbore at the surface of the well. Thereafter, thesteam travels down the tubing string 205 where it is utilized at eachzone by a pocket 210 and nozzle 215 as illustrated in FIGS. 2-4.

Returning to FIG. 2, the invention utilizes a plurality of apertures 220in the tubing 205 and apertures 230 in the sleeve 225 in order tofacilitate the passage of steam from the tubing to the pocket 210 in amanner whereby the steam retains its predetermined proportions of vaporand water. At a certain velocity, steam made up of water and vapor willseparate with the water collecting and traveling in an annular fashionalong the outer wall of the tubular. FIG. 6 illustrates that phenomenon.As shown, vapor and water particles 260 travel in the center of thetubing 205 while the water 265 travels along with inner wall thereof.The path of the water and vapor from the tubing through the apertures isshown with arrows 270. The apertures are sized, numbered and spaced in away whereby the proportion of water to vapor is retained as the steampasses into the pocket (not shown) and is thereafter injected into theformation around the wellbore. As described herein, the number ofapertures utilized for a particular operation can be determined by usinga sleeve having a desired number of apertures to align with theapertures of the tubing.

FIG. 7 is a section view of an apparatus 500 of the present inventiondisposed in a lateral wellbore 491. As shown in FIG. 7, the lateralwellbore 491 is formed by directional drilling from a vertical wellbore400 to extend outward essentially horizontally from the verticalwellbore 400. Disposed within the vertical and lateral wellbores 400,491 is a tubing string 505. The tubing string 505 is typically coaxialwith the vertical wellbore 400, but rests on the bottom of the lateralwellbore 491 so that the axis of the tubing string 505 is substantiallyparallel to the axis of the lateral wellbore 491. A steam generator 150is located at the surface of the well and a choke 155 regulates the flowof the steam into the tubing string 505. The portion of the tubingstring 505 located within the vertical wellbore 400 is depicted withoutthe apparatus 200 described above in reference to FIGS. 2-6; however, itis understood that the tubing string 505 may include the apparatus 200disposed within the vertical wellbore 400 along with the apparatus 500disposed within the lateral wellbore 491.

In the embodiment of FIG. 7, the tubing string 505 includes threeenlarged areas or pockets 510 formed therein, each defining an annulararea with the casing and including a nozzle 515 at one end. The tubingstring 505 may include any number of pockets 510. The pockets 510 areessentially concentric to allow another tubular body of a given diameterto slide over the tubing string 505. For example, a washover stringplaced around the tubing string 505 to clean sand out of the annulararea between the tubing string 505 and the wellbore 491 is oftendesirable to utilize in wellbore operations. Concentric pockets 510permit a washover string of smaller diameter to be used than thediameter required for a washover string used with the pockets 210 ofFIGS. 2-6.

The pockets 510 are placed at regular intervals along the length of thelateral wellbore 491. Each of the pockets 510 is preferably formed in asub that can be located in the tubing string 505 and subsequentlypositioned adjacent the zone of interest. Each nozzle 515 provides fluidcommunication between the apparatus 500 and perforations 410 in the zoneof interest. The distribution of pressure within the horizontalinjection zone is caused to be more uniform by the use of multiple subsinjecting steam into the annulus of the wellbore at regular intervals.Uniform pressure in the wellbore causes uniform flow of steam into thezone of interest throughout the length of the lateral wellbore 491. Theinjection of steam in this manner is preferable to the non-uniform steaminjection that is produced by an open casing with higher pressure at theheel than at the toe of the lateral wellbore 491. The number of subsutilized depends upon the degree of injection uniformity that isdesired. The subs are connected within the tubing string 505 by threadedconnectors 517 at each end.

Encumbering members 492 are disposed on the tubing string 505 acrossfrom the blowing end of each nozzle 515, as shown in FIGS. 7-8. Theencumbering members 492 disrupt the velocity and jetting action of thenozzle 515 so that steam is supplied to the annulus without flowpreference in the direction of the nozzle 515. Encumbering members 492are included so that the steam is injected into the formation at asubstantially uniform pressure and flow rate along the length of thewellbore 491.

FIG. 8 shows a portion of the apparatus of FIG. 7 including the tubingstring 505 and one of the pockets 510. Each nozzle 515 possesses athroat 550 and diffuser portion 545 to efficiently use the steam, asdescribed above in relation to FIGS. 2-6. Also as described above, thenozzle 515 is threadingly engaged or clamped in the pocket 510 andsealed therein with a seal ring (not shown). A plurality of apertures520 formed in a wall of the tubing string 505 adjacent the pocket 510provide fluid communication between the tubing string 505 and the pocket510. If the tubing string 505 shown in FIGS. 2-6 were utilized in alateral wellbore 491, the steam would separate into water and vaporalong the length of the lateral wellbore 491 from a heel 551 of thelateral wellbore 491 to a toe 552 of the lateral wellbore 491. The waterportion of the steam tends to flow in the lower portion of the tubingstring 505 along its length, while the vapor tends to flow in the upperportion of the tubing string 505 along its length. The separation of thewater portion from the vapor portion along the length of the tubingstring 505 results in different treatment of each area of interest withthe steam, depending upon whether the apertures 520 are oriented nearthe bottom or the top of the pocket 510. To prevent this problem fromoccurring, the apertures 520 are distributed circumferentially aroundthe pocket 510 so that some of the apertures 520 are always located nearboth the bottom and the top of the pocket 510, regardless of theorientation of the pocket 510 in the horizontal wellbore 491.

Also included in the apparatus of FIG. 8 is a sleeve 525 located insidethe pocket 510 which is preferably fitted into the perforated inner flowconduit 531 prior to run-in of the apparatus 500. An enlarged view ofthe sleeve 525 is illustrated in FIG. 9. The sleeve 525 possesses aplurality of apertures 530 which are circumferentially distributedaround the sleeve 525. The apertures 530 of the sleeve 525 may bealigned with the apertures 520 in the perforated inner flow conduit 531to pass a given amount of steam therethrough to treat the zone ofinterest. The apertures 520, 530 facilitate the passage of steam fromthe perforated inner flow conduit 531 to the pocket 510 so that thesteam retains the proportions of vapor and water predetermined at thesurface of the wellbore. The apertures 520 are numbered, sized, andspaced so that the proportion of water and vapor present in the steamremains the same as the steam passes into the pocket 510 and isthereafter injected into the area of interest in the formation. Thesleeve 525 may be employed to select the number of apertures 520 usedfor a particular operation. Fewer apertures 530 in the sleeve 525produce proportional steam quality when used with nozzles 515 having asmaller diameter throat 550. Alternatively, more apertures 530 areneeded when used with nozzles 515 having larger diameter throats 550. Byinstalling a sleeve 525 with an appropriate number, size, anddistribution of apertures 530 for a particular size (throat diameter) ofnozzle 515, it is possible to produce the desired liquid/vapor ratiowith any particular nozzle 515. Therefore, a range of nozzle 515 sizesmay be used without the need to produce a different pocket 510 which isappropriate for each size (throat diameter) of nozzle 515.

Because the apertures 530 are circumferentially distributed, fluidcommunication exists around the diameter of the perforated inner flowconduit 531 when the apertures 520 and 530 are aligned so that a uniformdistribution of water and vapor treats each area of interest along thelateral wellbore 491. A larger number of apertures 520 may exist in theperforated inner flow conduit 531 than the number of apertures 530 thatexist in the sleeve 525, but the apertures 520 which are covered by thesleeve 525 are rendered ineffective. Only the apertures 520 which alignwith the apertures 530 in the sleeve 525 are open to allow flow of steamtherethrough. In this way, the sleeve 525 permits selective use of theapertures 520 depending upon the amount of steam (diameter of nozzle)needed in the zone of interest.

The sleeve 525, as described above in relation to FIGS. 2-6, may havefewer apertures 530 than the apertures 520 in the perforated inner flowconduit 531 to adjust the liquid/vapor ratio of the steam that flows outof the pocket 510. The characteristics of the steam at a particularpocket 510 may be determined by utilizing a sleeve 525 with more orfewer apertures 520 rather than fabricating separate pockets 510 foreach application. The sleeve 525, much like the sleeve 225, is sealedwithin the tubing string 505 by seal rings 527 located at each of itsends. Moreover, the apertures 520 and 530 are rotationally aligned by aslot and pin arrangement 644 between the sleeve 525 and the tubingstring 505.

In use, as shown in FIG. 7, the apparatus 500 delivers steam from thesteam generator 150 located at a surface 554 of the well to the zone ofinterest, while ensuring that the length of the zone of interestreceives a predetermined amount of steam at a nearly constant pressure.The amount of steam injected into the zone of interest along the lengthof the lateral wellbore 491 is determined by the supply pressure at thesurface and the characteristics of the nozzle 515. The nozzle 515 is thesame as the nozzle 215, and therefore imparts the same advantages overprior art nozzles within the lateral wellbore 491 of FIGS. 7-8 as withinthe vertical wellbore 100 of FIGS. 2-6. As such, FIG. 5 applies equallyto the apparatus 500 of FIGS. 7-8.

Specifically, steam is supplied from the steam generator 150 into thetubing string 505. The steam flows through the vertical wellbore 400portion of the tubing string 505 and into the lateral wellbore 491portion of the tubing string 505. Alternatively, the steam flows throughthe tubing string which has been disposed in the directionally drilledportion of the formation. Referring to FIG. 8, the flow of the steamthrough a portion of the apparatus 500 is represented by arrows. Thesteam travels through the tubing string 505, then enters the sleeve 525.The steam then flows through the apertures 530 and through the apertures520 into the pocket 510. The steam next flows into the area with theleast obstruction, namely the portion of the pocket 510 with the nozzle515 connected thereto.

The steam then flows further downstream after exiting the nozzle 515until it is hindered by the encumbering member 492. The encumberingmember 492 forces a portion of the steam to remain in between the nozzle515 and the encumbering member 492, so that the whole of the steam doesnot flow in the direction in which the nozzle 515 dispenses the steam.In this way, the pressure and flow rate of the steam is more equallydistributed along the length of the zone of interest.

FIGS. 10A-10D illustrate a method and apparatus for remotely disposing anozzle assembly in a pocket formed in a side of a tubular body. Themethod is particularly valuable when formation conditions change and itbecomes desirable to decrease or increase the amount of steam injectedinto a particular zone. With the apparatus described and shown, a nozzlewith different characteristics can be placed in the wellbore withminimal disruption to operation. FIG. 10A is a section view illustratinga section of tubing 205 with a pocket 210 formed on a side thereof.Locatable in the pocket is a nozzle assembly 300 which includes a nozzle301 which is sealingly disposable in an aperture 302 formed between anouter wall of the tubular and the inner wall of the pocket 210. Thenozzle has the same throat and diffuser portions as previously describedin relation to FIG. 4. At an upper end of the nozzle assembly is a latch341 for connection to a “kick over” tool 307 which is constructed andarranged to urge the nozzle assembly 300 laterally and to facilitate itsinsertion into the pocket. The kick over tool includes a means forattachment to the nozzle assembly 300 as well as a pivotal arm 320 whichis used to extend the nozzle assembly 300 out from the centerline of thetubular 205 and into alignment with the pocket 210. In FIG. 10A, thenozzle assembly 300 is shown in a run in position and is axially alignedwith the centerline of the tubular 205. In FIG. 10B, the kick over tool307 has been actuated, typically by upward movement from the surface ofthe well, and has been aligned with and extended into axial alignmentwith the pocket 210. In FIG. 10C, downward movement of the nozzleassembly 300 has located the nozzle 301 in a sealed relationship (seal342) with a seat 302 formed at a lower end of the pocket 210. In FIG.10D, a shearable connection between the nozzle assembly 300 and the kickover tool 307 has been caused to fail and the kick over tool 307 can beremoved from the wellbore, leaving the nozzle assembly 300 installed inthe pocket 210.

In addition to installing and removing a modular nozzle, the embodimentof FIGS. 10A-10D also provide a remotely installable and removablesleeve having apertures in a wall thereof. In this manner, the nozzlecan be installed in the pocket without interference. In one aspect, thesleeve is removed from the apparatus in a separate trip before thenozzle is removed. In another aspect, the sleeve is returned to theapparatus and installed after the nozzle has been installed.

FIG. 11 illustrates a removable sleeve 350 in the tubing 205 between theinterior of the tubing and the nozzle assembly 300. The sleeve includesapertures 355 formed in a wall thereof to control the proportionate flowof steam components as described previously. Also visible is a run intool 340 used to install and remove the sleeve and a pin and slotarrangement 343, 344 permitting the sleeve to be placed and then left inthe apparatus. Typically, the removable sleeve 350 is inserted adjacentthe pocket 210 after the removable nozzle assembly 300 has beeninstalled. Conversely, the sleeve 350 is removed prior to the removal ofthe nozzle assembly 300.

It will be understood that while the methods and apparatus of FIGS.10A-10D and 11 have been discussed as they would pertain to installing anozzle, the same methods and apparatus are equally usable removing anozzle assembly from a pocket formed on the outer surface of a tubularand the invention is not limited to either inserting or removing anozzle assembly. Furthermore, while the methods and apparatus of FIGS.10A-D and 11 have been discussed as pertaining to the apparatus 200 ofFIGS. 2-6, the same methods and apparatus are equally usable in theapparatus 500 for use in a lateral wellbore 491 depicted in FIGS. 7-8.

In addition to providing a controlled flow of steam to multiple zones ina single wellbore, the nozzle of the present invention can be utilizedat the surface of the well to provide a controlled flow of steam from asingle steam source to multiple wellbores. In one example, a steamconduit from a source is supplied and a critical flow-type nozzle isprovided between the steam source and each separate wellbore. In thismanner, a controlled critical flow of steam is insured to each wellborewithout interference from pressure on the wellbore side of the nozzle.

In addition to providing a means to insure a controlled flow of steaminto different zones in a single wellbore, the apparatus describedtherein provides a means to prevent introduction of steam into aparticular zone if that becomes necessary during operation of the well.For instance, at any time, a portion of tubing including a pocketportion can be removed and replaced with a solid length of tubingcontaining no apertures or nozzles for introduction of steam into aparticular zone. Additionally, in the embodiment providing removablenozzles and removable sleeves, a sleeve can be provided without anyapertures in its wall and along with additional sealing means, canprevent any steam from traveling from the main tubing string into aparticular zone. Alternatively, a blocking means can be provided that isthe same as a nozzle in its exterior but lacks an internal flow channelfor passage of steam.

In order to install a particular sleeve adjacent a particular pocket,the sleeves may be an ever decreasing diameter whereby the smallestdiameter sleeve is insertable only at the lower most or furthestdownstream zone. In this manner, a sleeve having apertures designed foruse with in a particular zone cannot be inadvertently placed adjacentthe wrong zone. In another embodiment, the removable sleeves can use akeying mechanism whereby each sleeve's key will fit a matching mechanismof any one particular zone. In one example, the keys are designed tolatch only in an upwards direction. In this manner, sleeves areinstalled by lowering them or moving them downstream to a position inthe wellbore below the intended zone. Thereafter, as the sleeve israised or moved upstream in the wellbore, it becomes locked in theappropriate location. These types of keying methods and apparatus arewell known to those skilled in the art.

While the foregoing is directed to embodiments of the present invention,other and further embodiments of the invention may be devised withoutdeparting from the basic scope thereof, and the scope thereof isdetermined by the claims that follow.

1. An apparatus for injecting steam from a wellbore into a geologicalformation, the apparatus comprising: a flow path between a well surfaceand the formation, the flow path including at least one nozzle, the atleast one nozzle including a throat portion and a diffuser portion,whereby the steam will flow through the nozzle at a critical flow rate.2. The apparatus of claim 1, wherein the apparatus injects steam from alateral wellbore into the formation.
 3. The apparatus of claim 1,wherein the critical flow rate is a controlled flow rate.
 4. Theapparatus of claim 3, wherein the flow path includes a string oftubulars extending from the well surface to the formation, the at leastone nozzle located in the string of tubulars, proximate the formation.5. The apparatus of claim 4, wherein the fluid path further includes afluid path formed in a wall of a casing lining the wellbore, the fluidpath formed adjacent the formation.
 6. The apparatus of claim 5, whereinthe fluid path formed in the casing includes perforations.
 7. Theapparatus of claim 4, further including at least one opening formedalong the string of tubulars proximate the formation, the at least onenozzle connected to the at least one opening.
 8. The apparatus of claim7, wherein the at least one opening includes an enlarged area or apocket.
 9. The apparatus of claim 8, wherein the enlarged area isdisposed circumferentially around the string of tubulars.
 10. Theapparatus of claim 9, wherein a portion of the string of tubulars withinthe enlarged area has apertures disposed therein which arecircumferentially distributed around the string of tubulars.
 11. Theapparatus of claim 10, wherein the number of apertures in the tubularstring is variable and selectable.
 12. The apparatus of claim 11,further including an intermediate sleeve member disposable in thetubular string adjacent the apertures in the wall, the intermediatesleeve member having circumferentially distributed apertures alignablewith the apertures in the wall.
 13. The apparatus of claim 12, whereinthe apertures in the sleeve are constructed and arranged to permit steamto pass from the tubing to the pocket while maintaining a predeterminedratio of water and vapor.
 14. The apparatus of claim 9, wherein at leasttwo pockets are disposed along the tubular string.
 15. The apparatus ofclaim 8, further including a wall between an interior of the tubing andthe at least one opening, the wall having at least one aperture formedtherein.
 16. The apparatus of claim 15, wherein the number of aperturesin the wall between the tubing and the pocket is variable andselectable.
 17. The apparatus of claim 16, further including anintermediate sleeve member disposable in the tubular string adjacent theapertures in the wall, the intermediate sleeve member having aperturesalignable with the apertures in the wall.
 18. The apparatus of claim 17,wherein the steam is saturated steam.
 19. The apparatus of claim 18,wherein the steam includes a component of water and a component ofvapor.
 20. The apparatus of claim 17, wherein the apertures in thesleeve are constructed and arranged to permit steam to pass from thetubing to the pocket while maintaining a predetermined ratio of waterand vapor.
 21. The apparatus of claim 20, wherein the apertures in thewall between the tubing and the pocket are substantially perpendicularto a longitudinal axis of the tubing.
 22. The apparatus of claim 21,wherein the flow of fluid through the nozzle is approximately parallelto the longitudinal axis of the tubing.
 23. The apparatus of claim 8,wherein there are at least two pockets disposed along the tubular stringand an annular area between each pocket and an adjacent formation isisolated with a packing member.
 24. The apparatus of claim 8, whereinthe nozzle is remotely removable.
 25. The apparatus of claim 8, whereinthe nozzle is remotely insertable.
 26. An apparatus for injecting steamat a controlled flow rate into a geological formation, the apparatuscomprising: a flow path between a well surface and the formation, theflow path including at least one opening, the opening permitting steamflow at a critical flow rate with an annulus/tubing pressure ratio of upto about 0.9 by using a throat and diffuser portion in the opening. 27.The apparatus of claim 26, further comprising an obstructing memberdisposed across from the nozzle which urges the steam along the flowpath into the formation.
 28. A method of injecting steam into ageological formation comprising: introducing the steam into a wellborelined with casing, the wellbore including at least one zone of interestand the casing having perforations adjacent the at least one zone; andflowing the steam through a nozzle at a critical flow rate from a stringof tubing to the perforations, the nozzle having a throat portion and adiffuser portion.
 29. The method of claim 28, wherein the critical flowrate is maintained when an annulus/tubing ratio is greater than about0.56.
 30. The method of claim 29, wherein the steam is introduced at apressure adequate to overcome a natural pressure and impermeabilitypresent in any of the at least one zone of interest.
 31. The method ofclaim 28, further including causing a flow of the steam through thetubing whereby a water component of the steam travels in an annularfashion along an inner wall of the tubing.
 32. The method of claim 30,further including removing the nozzle and replacing it with a secondnozzle.
 33. An apparatus for injecting steam at a controlled rate intomultiple zones of interest adjacent a wellbore, the apparatuscomprising: a tubular string for transporting steam into the wellborefrom the surface of the well; at least two nozzles disposed along thestring, each nozzle located in that position of the wellbore adjacent afirst and second zones of interest, the nozzles having a throat portionand a diffuser portion.
 34. The apparatus of claim 33, further includingsealing means isolating an annular area above and below each nozzle, theannular area formed between the tubular and walls of the wellbore. 35.The apparatus of claim 33, further comprising an obstructing memberdisposed downstream from each nozzle, wherein the obstructing memberhinders a portion of the fluid from flowing downstream in thepreferential direction of each nozzle.
 36. An apparatus for injectingsteam into multiple wellbores from a single source of steam, theapparatus comprising: a fluid path from the source of steam to eachwellbore; and at least one nozzle between the source and each wellbore,the at least one nozzle including a throat and a diffuser portionproviding a predetermined flow rate of steam to each wellbore.
 37. Anapparatus for injecting steam from a source of steam to at least twowellbores, the apparatus comprising: a flow path for the steam betweenthe source of steam and the at least two wellbores; at least one nozzlein the flow path, the nozzle for controlling a flow of steam usingcritical flow.
 38. The apparatus of claim 37, wherein there are an equalnumber of nozzles and wellbores.
 39. The apparatus of claim 37, whereinthe at least one nozzle includes a throat portion and a diffuserportion.
 40. An apparatus for injecting steam into a lateral wellborecomprising: a tubular string; at least one pocket formedcircumferentially around the tubular string; and at least one nozzledisposed on the tubular string, the at least one nozzle including athroat portion and a diffuser portion.
 41. The apparatus of claim 40,further comprising at least one aperture in the tubular string toprovide fluid communication between the inner diameter of the tubularstring and the at least one pocket.
 42. The apparatus of claim 41,further comprising a plurality of apertures disposed circumferentiallyaround the tubular string to provide fluid communication between theinner diameter of the tubular string and the at least one pocket. 43.The apparatus of claim 42, further comprising at least one sleeve memberdisposable in the tubular string adjacent the plurality of apertures,wherein the at least one sleeve member comprises a plurality ofapertures disposed circumferentially therearound.
 44. The apparatus ofclaim 43, wherein the plurality of apertures in the at least one sleevemember are alignable with the plurality of apertures in the tubularstring to permit steam to flow from the tubular string to the at leastone pocket to maintain a predetermined ratio of water and vapor injectedinto a geological formation through each of at least two nozzles. 45.The apparatus of claim 40, further comprising at least one obstructingmember disposed on the tubular string across from the at least onenozzle.
 46. The apparatus of claim 45, wherein the at least oneobstructing member prevents a portion of the steam from flowing in adirection in which the steam is dispensed from the at least one nozzle.